Horizontal well drilling and production have become increasingly important to the oil industry in recent years. While horizontal wells have been known for many years, only relatively recently have such wells been determined to be a cost-effective alternative to conventional vertical well drilling. Although drilling a horizontal well costs substantially more than its vertical counterpart, a horizontal well frequently improves production by a factor of five, ten or even twenty in naturally-fractured reservoirs. Generally, projected productivity from a horizontal wellbore must triple that of a vertical wellbore for horizontal drilling to be economical. This increased production minimizes the number of platforms, cutting investment and operational costs. Horizontal drilling makes reservoirs in urban areas, permafrost zones and deep offshore waters more accessible. Other applications for horizontal wellbores include periphery wells, thin reservoirs that would require too many vertical wellbores, and reservoirs with coning problems in which a horizontal wellbore could be optimally distanced from the fluid contact.
Also, some horizontal wellbores contain additional wellbores extending laterally from the primary vertical wellbores. These additional lateral wellbores are sometimes referred to as drainholes and vertical wellbores containing more than one lateral wellbore are referred to as multilateral wells. Multilateral wells are becoming increasingly important, both from the standpoint of new drilling operations and from the increasingly important standpoint of reworking existing wellbores, including remedial and stimulation work.
As a result of the foregoing increased dependence on and importance of horizontal wells, horizontal well completion, and particularly multilateral well completion, have been important concerns and continue to provide a host of difficult problems to overcome. Lateral completion, particularly at the juncture between the main and lateral wellbores, is extremely important to avoid collapse of the wellbore in unconsolidated or weakly consolidated formations. Thus, open hole completions are limited to competent rock formations; and, even then, open hole completions are inadequate since there is no control or ability to access (or reenter the lateral) or to isolate production zones within the wellbore. Coupled with this need to complete lateral wellbores is the growing desire to maintain the lateral wellbore size as close as possible to the size of the primary vertical wellbore for ease of drilling and completion.
The above concerns can be summarized in three main objectives: connectivity, isolation and access. Connectivity refers to the mechanical coupling of casings in the main and lateral wellbores such that there are no open holes between casings. This ensures that the multilateral completion is not subject to collapse of a section of open hole and that open hole tools are not required to access portions of the completion.
Isolation refers to the ability to seal off one or more wellbores, or any selectable portion thereof, without impeding production from remaining wellbores or portions. To isolate one wellbore from another effectively, the casings in the wellbores must be hydraulically sealed (generally up to 5000 psi) to one another to allow the multilateral completion as a whole to withstand hydraulic pressure. Hydraulic sealing is particularly important at the juncture between main and lateral wellbores. Without hydraulic sealing, either pressure is lost into the void that surrounds the casing or fluid or particulate contaminates are allowed to enter the casing from the surrounding void. While connectivity, isolation and access are important in both horizontal and vertical wells, they are particularly important and pose particularly difficult problems in multilateral well completions. As mentioned above, isolating one lateral wellbore from other lateral wellbores is necessary to prevent migration of fluids and to comply with completion practices and regulations regarding the separate production of different production zones. Zonal (or partial wellbore) isolation may also be needed if the wellbore drifts in and out of the target reservoir because of insufficient geological knowledge or poor directional control. When horizontal wellbores are drilled in naturally-fractured reservoirs, zonal isolation is seen as desirable. Initial pressure in naturally-fractured formations may vary from one fracture to the next, as may the hydrocarbon gravity and likelihood of coning. Allowing the formations to produce together permits crossflow between fractures. A single fracture with early water breakthrough may jeopardize the entire well's production.
Access refers to the ability to reenter a selected one of the wellbores to perform completion work, additional drilling or remedial and stimulation work, preferably without requiring a full drilling rig. In the most preferable situation, any one of the lateral wellbores can be entered using coiled tubing, thereby saving money.
There have been several prior art techniques of completing multilateral wells using open-hole completion techniques. One involves the drilling of a single main wellbore and one or more lateral wellbores emanating from a base portion thereof. The main wellbore is cased except for the base portion. The base portion and the one or more lateral wellbores are left open-hole. Although this completion technique is relatively inexpensive, not one of the above three main objectives (connectivity, isolation and access) is satisfied, as there are portions of the wellbores left open-hole, the open-hole wellbores cannot be selectively sealed off, except to a limited degree with open-hole isolation tools and access to the lateral wellbores can only be by way of bent subs or orientation devices. Apart from the three main objectives, if one of the lateral wellbores collapses or becomes clogged, the entire well is threatened.
Another prior art completion technique calls for the drilling of one or more open hole lateral wellbores from a main wellbore. A special casing having a number of inflatable open-hole packers and perforations between the inflatable packers is placed in the main wellbore. The inflatable packers serve to separate the lateral wellbores hydraulically from one another. This technique therefore offers a degree of isolation, in that an entire lateral can be sealed off from the rest. However, portions of a lateral cannot be sealed off. Further, there is neither connectivity nor access. Finally, the lateral wellbores are left open-hole. Therefore, if a lateral wellbore collapses or becomes clogged, production from that wellbore is compromised.
Conventionally, some multilateral completion techniques have employed slotted liner completion. The primary purpose of inserting a slotted liner in a lateral wellbores is to guard against hole collapse. Additionally, a liner provides a convenient path to insert various tools such as coiled tubing in the wellbore. Three types of liners have been used, namely: (1) perforated liners, where holes are drilled in the liner, (2) slotted liners, where slots of various width and length are milled along the line length, and (3) prepacked screens.
One prior art completion technique employing liners is similar to the first-described open-hole completion technique, but requires the lateral wellbores to be fitted with liners. However, the liners terminate within the lateral wellbores, resulting in short lateral wellbore sections proximate the main wellbore that are left open-hole. Similarly, the base portion of the main wellbore is left open-hole. Although not as inexpensive as the first-described open-hole technique, this completion technique is still relatively inexpensive. However, none of the above three main objectives is satisfied, as portions of each lateral wellbore and the base portion of the main wellbore are left open-hole. The open-hole wellbores cannot be selectively sealed off, except to a limited degree with open-hole isolation tools. Finally, access to the lateral wellbores can only be by way of bent subs or orientation devices. The sole advantage of this completion technique is that liners provide support as against erosion or collapse in the lateral wellbores.
A second completion technique employing lined laterals involves two lateral wellbores extending from a main wellbore, one over the other, each having a liner and each liner extending back to a casing in the main wellbore. Thus, connectivity is achieved, as the liners are hydraulically sealed to the main wellbore casing. Unfortunately, the lower of the two lateral wellbores cannot be sealed off (isolated). Further, the lower of the two lateral wellbores cannot be accessed subsequently. Thus, only one of the three principal objectives is met.
A third completion technique employing lined laterals is reserved for new well completion and involves the drilling of multiple lateral wellbores from a main wellbore. A liner is inserted into the main wellbore. The liner is provided with windows therein corresponding to the position of the laterals. Thus, the main wellbore liner must be oriented when it is inserted. Next, liners are inserted into the lateral wellbores. The open ends of the lateral wellbore liners extend through the windows of the main wellbore liner. This technique is designed for new wells, because the location and orientation of the lateral wellbores must be prearranged. Applying the three main objectives, connectivity is not present, since the lateral wellbore liners are not sealed to the main wellbore liner. Isolation is possible, but access to the lateral wellbores for the purpose of reworking or isolating a lateral wellbore must be made by way of bent subs or orientation devices.
One further prior art completion technique does not involve either open-hole or lined lateral wellbores. This technique requires the drilling of a relatively large main wellbore. Multiple lateral wellbores are drilled in parallel through the bottom of the main wellbore and spread in separate directions. The main and lateral wellbores are cased and sealed together. All three of the three main objectives are met, as isolation of and access to each lateral wellbore are provided. However, in most cases, only two or three lateral wellbores are allowed, as the cross-sectional areas of the lateral wellbores must fit within the cross-sectional area of the main wellbore. This severely limits the cost effectiveness of the well as a whole, as the main wellbore must be of exceptionally large diameter and thus relatively expensive to drill.
The problem of lateral wellbore (and particularly multilateral wellbore) completion has been recognized for many years as reflected in the patent literature, For example, U.S. Pat. No. 4,807,704 discloses a system for completing multiple lateral wellbores using a dual packer and a deflective guide member. U.S. Pat. No. 2,797,893 discloses a method for completing lateral wells using a flexible liner and deflecting tool. U.S. Pat. No. 2,397,070 similarly describes lateral wellbore completion using flexible casing together with a closure shield for closing off the lateral. In U.S. Pat. No. 2,858,107, a removable whipstock assembly provides a means for locating (e.g., accessing) a lateral subsequent to completion thereof. U.S. Pat. No. 3,330,349 discloses a mandrel for guiding and completing multiple horizontal wells. U.S. Pat. Nos. 4,396,075; 4,415,205; 4,444,276 and 4,573,541 all relate generally to methods and devices for multilateral completions using a template or tube guide head. Other patents of general interest in the field of horizontal well completion include U.S. Pat. Nos. 2,452,920 and 4,402,551.
Ser. No. 08/296,941, initially referenced above, discloses several methods and systems for subterranean multilateral well drilling and completion. Of two main embodiments of such methods and systems, the latter, in a preferred embodiment, employs a drillable composite joint or liner that extends from the main borehole and through a window in the main borehole into the lateral borehole. In place, the liner blocks a lower portion of the main borehole. After being cemented into place, a portion of the liner must be removed, preferably by drilling through the portion with an ordinary rock bit, to reopen the lower portion of the main borehole.
However, simply providing a drillable composite tube as a liner has significant disadvantages. First, such liners must be cemented in place and thus must have an outer diameter substantially less than an inner diameter of the surrounding main casing to allow for the cement. However, given such room within the main casing, the liner tends to wander radially within the main casing, thereby causing the liner to decentralize. This is disadvantageous, because the cement may not be distributed about the liner evenly, thereby compromising the strength of the cement bond. The prior art has provided metallic spacers that may be fitted to the liner at periodic points about its length. However, the metallic spacers are not drillable by a conventional rock bit and therefore present an obstacle if a spacer happens to be at the portion of the liner that is to be removed. Furthermore, such metallic spacers are local and do not run the full length of the liner.
Second, as cement is introduced into the annular space between the outer diameter of the liner and the inner diameter of the main casing or lateral borehole, impurities or voids may also be introduced. Typically, the voids will be caused by well fluids that displace the cement or occur because the cement settles. This may be more pronounced in lateral or horizontal wellbore sections in which the heavier cement settles to the lower areas about the casing and formation fluids rise to the upper areas resulting in voids in the cement in the upper areas. Optimally, the impurities should be mixed throughout the cement to decrease their detrimental effects. The prior art has provided turbulence devices substantially comprising metallic fins that, like the spacers, may be fitted to the liner at periodic points about its length. However, the metallic fins are not drillable by a conventional rock bit and therefore also present an obstacle if a turbulence device happens to be at the portion of the liner that is to be removed. Furthermore, as with the metallic spacers, such turbulence devices are local and do not run the full length of the liner.
Thus, what is needed in the prior art is a composite joint or liner that is drillable by an ordinary rock bit, but that includes features directed to centralizing the liner within the main casing and to providing turbulence and mixing to the cement that is eventually to surround the liner.